The present invention relates to methods and compositions useful in subterranean treatments, and more particularly, the present invention relates to the use of antiflocculation additives to reduce the tendency of friction reducing polymers used in subterranean treatments to form undesirable flocs. The term “antiflocculation additive” as used herein, refers to compositions capable of reducing the tendency of friction reducing polymers to form undesirable flocs. The term “floc” as used herein, refers to a coagulated mass of particles in a liquid.
Aqueous treatment fluids may be used in a variety of subterranean treatments. Such treatments include, but are not limited to, drilling operations, stimulation operations, and completion operations. As used herein, the term “treatment,” or “treating,” refers to any subterranean operation that uses a fluid in conjunction with a desired function and/or for a desired purpose. The term “treatment,” or “treating,” does not imply any particular action by the fluid.
During the placement of aqueous treatment fluids into a well bore, a considerable amount of energy may be lost due to friction between the treatment fluid in turbulent flow and the formation and/or tubular goods (e.g., pipes, coiled tubing, etc.) disposed within the well bore. As a result of these energy losses, additional horsepower may be necessary to achieve the desired treatment. To reduce these energy losses, friction reducing polymers have heretofore been included in aqueous treatment fluids. The term “friction reducing polymer,” as used herein, refers to a polymer that reduces frictional losses due to friction between an aqueous fluid in turbulent flow and tubular goods (e.g. pipes, coiled tubing, etc.) and/or the formation. The term “polymer,” as used herein, is also intended to include both the acid form of the friction reducing polymer and its various salts. These friction reducing polymers may be synthetic polymers, natural polymers, or viscoelastic surfactants and are thought to reduce the friction between the aqueous treatment fluid in turbulent flow and the tubular goods and/or the formation.
One problem that may adversely affect friction reduction is the tendency of certain friction reducing polymers to function as flocculants. It is believed that the ionic nature of certain friction reducing polymers may cause these polymers to interact with formation fines and thereby form flocs. The resulting flocs may be undesirable because, among other things, the flocs may facilitate the formation of agglomerates that may clog pumps, filters, surface equipment and possibly plug fractures. Additionally, flocs may also reduce the fluid conductivity in the formation by adsorbing onto fracture faces within the formation or by possibly forming a stable emulsion in the formation that impacts subsequent production from the well bore.
An example of a subterranean treatment utilizing an aqueous treatment fluid is hydraulic fracturing. Hydraulic fracturing is a process commonly used to increase the flow of desirable fluids, such as oil and gas, from a portion of a subterranean formation. In hydraulic fracturing, a fracturing fluid is introduced into the subterranean formation at or above a pressure sufficient to create or enhance one or more fractures therein. Enhancing a fracture includes enlarging a pre-existing fracture in the formation. To reduce frictional energy losses between the fracturing fluid and/or the formation, friction reducing polymers may be included in the fracturing fluid. One type of hydraulic fracturing operation that may utilize friction reducing polymers is commonly referred to as a “high-rate water fracturing” operation. Typically, high-rate water fracturing is utilized in subterranean formations with low permeability (e.g., no more than about 0.1 millidarcy). Unlike conventional fracturing fluids, fluids used in high-rate water fracturing generally do not contain a sufficient amount of a water-soluble polymer to form a gel. Gel formation is based on a number of factors including the particular polymer and concentration thereof, temperature, and a variety of other factors known to those of ordinary skill in the art. As a result, the fracturing fluids used in these high-rate water fracturing operations generally have a lower viscosity than traditional fracturing fluids.